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Scanning Electron Microscopy (SEM) is used for source rock characterization to understand rock texture and compositional variations, porosity, and pore sizes. However, despite having significant benefits to characterization, obtaining quantitative results by SEM is time consuming and costly, and therefore the number of images collected per well is generally limited. Recent advances in image processing make obtaining quantitative data from images more accessible. This improves our ability to gather more image-based data on multiple wells for integration with larger scale measurements. Carbonate rich source rocks were sampled from several wells for SEM imaging. Large field-of-view SEM images were collected and segmented using supervised machine learning to label the pores, fractures/cracks, organics, high density minerals, and matrix minerals. Post-processing methods were used to correct mislabeled components. The relative amount of organic-contained porosity to total porosity (R1) and the relative amount of organic content to total porosity (R2) were calculated for each sample. Porosity was also obtained from crushed rock samples using the Gas Research Institute method. Pyrolysis was used to determine the productivity index and residual hydrocarbon content. Total porosity and organic content are two properties that are used to indicate rock quality. The results show that the R1 and R2 ratios from quantitative image-based analyses can be used to indicate potentially better quality. When compared across several wells of similar maturity, these quality metrics can be used to highlight wells with potentially better quality that warrant additional characterization. Finally, by comparing image-based data to that measured at larger scales, thermal maturity indicators can also be provided. This paper presents a method using image-based characterization to provide relative comparisons of reservoir quality between wells and a method to combine image-based and crushed rock analyses to compare source rock maturity. The results and workflow presented impact special core analysis for unconventional reservoirs and reservoir quality assessment and can complement characterization obtained by other methods.

Acoustic velocity measurements are an important non-destructive way to investigate dynamic rock mechanical properties. Water content and bedding-plane-induced anisotropy are reported to significantly impact the acoustic velocities of siliciclastic sandstones and laminated carbonates. This relationship in organic-rich shales however is not well understood and has yet to be investigated. The mechanical properties of organic-rich shales are affected by changes in water content, laminations, total organic content (TOC), and microstructures. In particular, kerogen density that accompanies changes in the composition of the TOC during maturity can significantly influence the acoustic responses within source rocks. To understand how these variables influence acoustic responses in organic shales, two sets of cores from the Eagle Ford shale were investigated: one set cut parallel to bedding and the other perpendicular to bedding. Textures of the samples from each set were characterized using CT scanning. NMR was used to measure the water content, and XRD to analyze the mineralogy. Scanning Electron Microscope (SEM) was also used to characterize the microstucture. Acoustic velocity measurements were then made on each set at various confining pressures using the ultrasonic pulse transmission technique. The results show that confining pressure, water content and laminations have significant impact on both compressional (P-wave) and shear wave (S-wave) velocity. Both velocities increase as confining pressure increases. Velocities measured from cores cut parallel to bedding are on average 20% higher than those cut perpendicular to bedding. Increasing water content decreases both velocities. The impact of water content on shear velocity was found to be significant compared to the response with compressional velocity. As a result, the water content was found to lower both Young's modulus and shear modulus, which is opposite to the reported results in conventional reservoir lithology. In addition, both P- and S- wave velocities show a linear decrease as TOC increases, and also they both decrease with increasing of clay content. The mechanisms that lead to water content alternation of rock mechanical properties might be a combined result of the clay-water interaction, the chemical reaction, and the capillary pressure changes.

The successful recovery of hydrocarbons from gas shales requires a fundamental understanding of the reservoir's rock-matrix properties. Information about the variable lithologies, mineralogies, and kerogen content is vital to locate favorable intervals for gas production. Knowledge of the in-situ stresses and porosity of these intervals is essential for developing hydraulic fracturing strategies to recover the gas in place. Often these properties are established from the analysis of cores extracted from the wellbore, a time-consuming practice which causes costly delays in well completions and prolonged rig time. We demonstrate that these reservoir rock properties can be measured and predicted in-situ from the wellbore environment by a formation evaluation method that employs a combination of measurements made by downhole geochemical, acoustic, and nuclear magnetic resonance sondes. Using this combination of tool measurements we determine lithology, mineralogy, and kerogen content. The mineralogy, porosity, acoustic velocities, bulk density, pore pressure, and overburden stress are then used to compute the unconfined compressive strength, Poisson's ratio, and horizontal stress for each interval. These results can then be used to develop hydraulic fracture strategies. The effectiveness of this approach is shown through characterization of the rock properties of the Caney and the Woodford Shale from three different wells. The ability to quantify the kerogen content from these formations is emphasized as there is currently no other direct quantification of carbon from openhole wireline logging available. This approach for characterization of shale gas reservoirs is also further supported through comparisons of core data that display the mineralogy, chemistry, kerogen content, and geomechanical properties from the wellbore section.

The assessment of reservoir productivity and subsurface hydrocarbon can be significantly enhanced through an understanding of formation mineralogy and organic carbon. Such information allows petrophysicists to resolve ambiguities in their predictions of reservoir hydrocarbon potential. While core samples are a prime source for exact formation mineralogy, excellent results can also be derived in a timely and cost-efficient manner from in-situ log chemistry measurements of the rock. A direct measurement of the formation's elemental concentrations is achieved using a gamma ray scintillation sensor in combination with a 14-MeV pulsed-neutron generator. The most important element measured is carbon, as it may provide a direct indication of reservoir hydrocarbons. This paper presents a method for determining the amount of organic carbon in subsurface formations using a pulsed-neutron mineralogy tool and a natural gamma ray spectroscopy tool. The natural, inelastic, and capture gamma ray energy spectra from these instruments are used to extract the chemistry of the subsurface formation being investigated. The elemental concentrations measured include Al, C, Ca, Fe, Gd, K, Mg, S, Si, Th, Ti, and U. Carbon is very difficult to measure without the inelastic spectrum generated from a pulsed-neutron source. An interpretation process, based upon the geochemistry of petroleum-bearing formations, is employed to derive the lithology and mineralogy which leads to the interpretation of the carbon measurement. The oil saturation can be computed in conventional reservoirs, assuming that the amount of carbon in excess of that required for the inorganic matrix mineralogy is part of the pore fluid as hydrocarbon. The direct carbon measurement is also important in laminated shaly sands or in low-salinity reservoirs, where oil saturation determination from indirect measurements, such as resistivity, is not compatible with the environment. In other formations the carbon can be determined to be a component of the rock matrix as kerogen or coal, both of which are uniquely identified with this logging system. Kerogen becomes extremely important in the evaluation of shale gas formations. Field examples are presented to illustrate the effectiveness of the carbon measurement.

This paper presents a methodology for characterizing the mineralogy and geomechanical properties of the Haynesville Shale. The results from two case study wells demonstrate how a perforating strategy based on mineralogy and geomechanical properties derived in part from mineralogy can improve hydraulic fracture stimulation performance. A full suite of openhole logs (acoustic, NMR, density-neutron, and mineralogy) provides the means for estimating both geomechanical properties and reservoir quality. An accurate measurement of total organic carbon with minimum core calibration is obtained from new wireline pulsed-neutron logging technology. Utilizing primarily openhole logging data, a micromechanical model simulates axial and radial deformations of a core sample under triaxial stress. It provides the static rock mechanical properties and strengths at different confining conditions for every depth interval. A new input to the micromechanical model is the mineralogy characterization derived from a wireline pulsed neutron tool. The static rock mechanical properties and TOC derived from these methods provide the key to understanding the fracturing potential of a zone in the Haynesville Shale. Two log examples show how optimized perforation placement based on these approaches can positively impact production. Tracer logs indicating vertical fracture containment and production data provide a validation of the approach. A post-mortem analysis of these well completions suggests that using the results of these models for fracture and completion design results in better production than wells completed differently in similar formations. The described approach brings together mineralogy, TOC, and mechanical rock properties for a complete evaluation of Haynesville Shale reservoirs with a view toward optimizing completion costs.

Gas shales are economically viable hydrocarbon prospects that have proven to be successful in North America. Unlike conventional hydrocarbon prospects, gas shales serve as the source, seal, and the reservoir rock. Generating commercial production from these unique lithofacies requires stimulation through extensive hydraulic fracturing. The absence of an accurate petrophysical model for these unconventional plays makes the prediction of economic productivity and fracturing success risky. This paper presents an integrated approach to petrophysical evaluation of shale gas reservoirs, specifically, the Barnett Shale from the Fort Worth basin is used as an example. The approach makes use of different formation evaluation data, including density, neutron, acoustic, nuclear magnetic resonance, and geochemical logging data. This combination of logging measurements is used to provide lithology, stratigraphy and mineralogy. It also differentiates source rock intervals, classifies depositional facies by their petrophysical and geomechanical properties, and quantifies total organic carbon. The analysis is also employed to locate optimal completion intervals, zones preferable for horizontal sections, and intervals of possible fracture propagation attenuation. Resistivity image analysis complements the approach with the identification of natural and drilling induced fractures. We compare results from three different wells to show the effectiveness of the method for shale gas characterization. The methodology presented provides a means to understand the geomechanical and petrophysical properties of the Barnett Shale. This knowledge can be used to design a selective completion strategy that has the potential to reduce fracturing expenses and optimize well productivity. Though developed specifically for the Barnett Shale, the underlying ideas are applicable to other thermogenic shale gas plays in North America.

A new openhole logging service, RockViewSM, has been developed which provides lithological and quantitative mineralogical information for accurate formation evaluation. The assessment begins with elemental formation weights and follows with an interpretation of lithology and mineralogy. Lithologies are divided into general categories including sand, shale, coal, carbonates, and evaporites. Potentially identifiable minerals are quartz, potassium-feldspar, albite, calcite, dolomite, siderite, anhydrite, illite/smectite, kaolinite, glauconite, chlorite, pyrite, and others. The logging system utilizes an electronic pulsed source to send high energy neutrons into the surrounding formation1-8. These neutrons quickly lose energy as a result of scattering, after which they are absorbed by the various atoms within the ambient environment. The scattered as well as the absorbed neutrons cause the atoms of the various elements to emit gamma rays with characteristic energies. These are measured with a scintillation detector, resulting in both inelastic and capture gamma ray energy spectra. A matrix inversion spectral fit algorithm is used to analyze these spectra in order to separate the total response into its individual elemental components. The prominent measured elements associated with subsurface rock formations include calcium, silicon, magnesium, carbon, sulfur, aluminum, and iron. Potassium, thorium, and uranium are measured separately with a natural gamma ray spectroscopy instrument9-11. The tool response is characterized for each individual element by placing it into formations of known chemical composition. Interpretation of the data begins with an assessment of the elemental formation weights, which then leads to a determination of lithology and mineralogy. Each step in the process is guided by the examination of ternary plots containing selected elements. Magnesium is an extremely important part of the interpretation process since it distinguishes dolomite from calcite and helps to identify various types of clay. Data from field examples is presented in order to illustrate the effectiveness of this technology.